VI. Storage Services

A. Introduction

For 2004, PG&E proposes that its storage assets21 continue to be allocated to the following three services: (1) Core Firm Storage service for CPGs; (2) system balancing service for the pipeline to provide monthly and daily balancing services; and (3) market storage services.

Under the Gas Accord, approximately 83% of PG&E's firm storage inventory rights, and associated firm injection and withdrawal rights, are assigned to PG&E's Core Procurement Department, for service to core customers. This firm storage is used to meet the winter reliability needs of core customers. Gas ESPs serving core customers are given the option to accept a proportionate share of the storage rights assigned to PG&E's Core Procurement Department. The gas ESPs contract directly with PG&E for the portion of Core Firm Storage rights accepted by gas ESPs under the provisions of PG&E's Schedule G-CFS. The remainder of PG&E's storage capacity is assigned to balancing, and to the noncore storage program (market storage services).22 (See 73 CPUC2d at pp. 805, 808-809; Ex. 1, p. 6-5, Table 6-1.)

Gas injection and withdrawal from PG&E's storage facilities vary depending on the amount of gas in inventory. During the injection season, the injection rights of PG&E's Core Procurement Department are reset every two weeks, and its withdrawal rights are reset every week through the withdrawal season, based on its level of inventory in storage. Because their storage inventory is such a small portion of total storage, PG&E allows gas ESPs to have a fixed injection and withdrawal profile through the injection and withdrawal seasons.

PG&E's market storage services provide firm and as-available storage service. As-available storage services include parking and lending, which are also known as hub services. These market storage services promote higher utilization of pipeline transportation services during the lower-demand, shoulder months of spring and fall.

After the Gas Accord was adopted, D.00-05-049 made two changes to storage services. The first change was to allow self-balancing. Under self-balancing, customers can choose to opt out of PG&E's monthly balancing service and match their supplies and demand on a daily basis and receive a credit from PG&E. As of December 31, 2002, no customer has elected to use the self-balancing service.

D.00-05-049 also changed the rules regarding Core Firm Storage. Gas ESPs were given the option to reject some or all of their allocations of the Core Firm Storage capacity. The costs of Core Firm Storage were unbundled from core customer transportation rates, and collected in bundled customers' procurement rates, and from gas ESPs that choose to accept storage allocations.

Under PG&E's proposal, storage rights for Monthly Balancing Service would increase compared to the Gas Accord. For Core Firm Storage, average injection and average withdrawal would increase, while inventory remains the same. For Standard Firm Storage, average injection and inventory for 2004 would increase, while withdrawal would decline. (See Ex. 1, Tables 6-1 and 6-2.)

2. Core Firm Storage Service

a. Basic Storage Services

PG&E proposes to expand the applicability of Schedule G-CFS to include PG&E's Core Procurement Department. This proposed change will ensure that all CPGs contract directly with PG&E's CGT for Core Firm Storage service, and are billed uniformly under the provisions of Schedule G-CFS. This change provides consistent treatment of CPGs for the assignment of both firm backbone and storage capacity. However, PG&E's Core Procurement Department will not have the option of rejecting its assignment of Core Firm Storage capacity, and will continue to receive any capacity rejected by gas ESPs.

For CPGs that accept an assignment of storage inventory of less than 1000 MDth, PG&E proposes to fix the firm injection and withdrawal rights for the season, as is done currently for small CPGs, instead of varying these rights with the customer's storage inventory level. The fixed withdrawal rights are set in proportion to the minimum withdrawal capacity that PG&E's Core Procurement Department must support, through the holding of inventory, to meet its Winter Firm Capacity Requirement. All CPGs that accept a share of Core Firm Storage capacity will be required to maintain their storage inventory at sufficient levels to support withdrawal rates consistent with the Winter Firm Capacity Requirement.

For CPGs with inventory levels beginning at approximately 1000 MDth, the physical injection and withdrawal capacities can vary significantly with the actual gas in inventory. A fixed injection or withdrawal right could intrude upon the storage rights of other customers. PG&E proposes that PG&E be allowed to vary the rights according to storage inventory levels for CPGs that obtain inventory rights greater than 1000 MDth.

No changes are proposed for how storage costs are recovered from bundled core customers or from gas ESPs. Bundled core customers will continue to pay for storage in their procurement rates, and gas ESPs that accept a storage assignment will pay a fixed monthly charge to PG&E.

b. Injection and Withdrawal Profiles for CFS

Table 6-3 of Exhibit 1 shows the capacity assigned to Core Firm Storage service for injection, inventory, and withdrawal, effective April 1, 2004. That table is reproduced below in Table 2. Overall, the average yearly ratio of injection to inventory to withdrawal is proposed to be 1.2:1:5.4. PG&E proposes that Schedule G-CFS injection and withdrawal rights vary based upon the volume of gas in inventory as shown in Table 2.

Table 2

Theoretical Service

Date

Injection

(MDth/d)

Estimated

Inventory

(MMDth)

Withdrawal

(MDth/d)

Firm Rights

Counter-Cyclical

(MDTH/d)

October 31

113

33.5

0

50 - withdrawal

November 1

0

33.5

1,442

50 - injection

January 15

0

13.2

1,150

50 - injection

February 15

0

6.2

1,000

50- injection

March 31

0

1.0

761

50 - injection

April 1

211

0

0

50 - withdrawal

As explained in the Cost Allocation and Rate Design section, the core storage rate will reflect this seasonal profile. PG&E notes that by reducing the firm rights to better reflect their seasonal use, the core storage rate will be less than it otherwise would be if a higher level of firm rights is assigned.

c. Firm Counter-Cyclical Storage
Rights for CFS

PG&E proposes to add firm counter-cyclical injection and withdrawal to Core Firm Storage service. The proposed service would provide 50 MDth/d of counter-cyclical rights for each day of the year. Table 2 above reflects the proposed counter-cyclical rights.

3. Standard Firm Storage Service

a. Basic Storage Services

PG&E proposes to develop a new tariff, Schedule G-SFS, Standard Firm Storage, to replace the existing Schedule G-FS, Firm Storage Service tariff. Proposed Schedule G-SFS provides more services than Schedule G-FS by offering more inventory, counter-cyclical injection and withdrawal rights, and the opportunity to secure a long-term contract.

PG&E proposes to offer a Schedule G-SFS customer firm injection, inventory, and withdrawal, in a fixed ratio of 2.2:1:3.1. (See Table 3.) This ratio defines the rate at which inventory can be filled and emptied, or injected and withdrawn. The withdrawal ratio is lower than that proposed for G-CFS because G-SFS customers do not require the high rate of withdrawal that is needed to meet residential and commercial temperature-sensitive demand.

By lowering the withdrawal ratio, all firm withdrawal rights can be met with lower pressure and a correspondingly lower inventory. Thus, less non-cycle working gas will be needed in the storage field to meet firm withdrawal rights. As a result, more gas in the storage field can be cycled as working gas, and more inventory can be offered to customers. The cycle inventory is the amount of gas that can typically be injected into and withdrawn from storage over the storage year, while supporting the injection and withdrawal rights of the firm storage customers. By reducing the withdrawal to inventory ratio for Schedule G-SFS, the inventory available to cycle can be increased from 40.5 MMDth to 47 MMDth.

PG&E believes that the increased cycle volume has more value to market storage services' customers than higher withdrawal rates. According to PG&E, these customers typically use storage services to control costs through price arbitrage in the seasonal cycles between spring and summer and fall and winter. They only need enough withdrawal capacity to withdraw their inventory during the high winter demand months of December through February and during the summer peak demand months of July through September. Core customers, on the other hand, derive more value from higher withdrawal rates in order to meet the temperature-sensitive daily winter demands of core customers from storage.

To increase the storage cycle inventory from 40.5 MMDth to 47 MMDth, PG&E will reassign 6.5 MMDth of non-cycle working gas. Of this gas, 2 MMDth will be retained and reclassified as working gas. This 2 MMDth of working gas will then be assigned to balancing, and used for the benefit of PG&E's transportation customers.

PG&E proposes that the remaining 4.5 MMDth of previously classified non-cycle working gas be sold to create room for customer owned gas. PG&E requests permission to sell the 4.5 MMDth of non-cycle working gas on a one-time basis for this purpose. PG&E proposes that any loss or gain from the sale of this non-cycle working gas be assigned to PG&E. PG&E's rationale for the assignment of any profit or loss on the sale of the gas to PG&E is because it owns the gas, and it has received only the short-term interest rate, rather than the utility authorized rate of return that is typical of most utility owned assets.

In Table 1, showing the assignment of firm storage rights effective April 1, 2004, more compression than is currently assigned under the Gas Accord will be needed to support the proposed 2004 firm storage rights. For 2004, PG&E proposes to use rental compressor units that were installed during the Gas Accord period to provide the additional firm injection. This rental compression added during the Gas Accord period is located below the flood plain at the McDonald Island storage facility.29

The Schedule G-SFS service will begin on April 1 of each year. The minimum term for G-SFS service will be one year, and service must be taken in one-year increments. The maximum term could be 15 years, as proposed below.

b. Injection and Withdrawal Profiles for SFS

Table 6-4 of Exhibit 1 shows the injection, inventory, and withdrawal rights curve for Standard Firm Storage service, effective April 1, 2004. That table is reproduced below in Table 3. Schedule G-SFS customers will be provided injection, inventory, and withdrawal in a fixed ratio of approximately 2.2:1:3.1. During the injection season, constant firm injection rights will be available to Schedule G-SFS customers until inventories are full. During the withdrawal season, each customer's constant firm withdrawal rights will be available, as long as gas volumes remain in that customer's contract inventory.

PG&E proposes to offer firm counter-cyclical injection and withdrawal rights as part of its standard firm services. PG&E believes that the proposed counter-cyclical service will allow noncore customers to more effectively manage their natural gas needs, especially for businesses that have multiple-season cycles, or business cycles that run counter to the traditional core seasonal cycle. Due to the differences in gas storage demand for Schedule G-CFS and Schedule G-SFS customers, PG&E is proposing different counter-cyclical profiles for the standard firm service offering. For Standard Firm Storage service customers, PG&E proposes to offer counter-cyclical rights with greater maximum daily capacities than Core Firm Storage customers, but to limit the number of days their firm counter-cyclical rights are available.

For 2004, PG&E proposes that Schedule G-SFS customers be able to choose any three months of firm counter-cyclical withdrawal rights during the injection season of April 1 through October 31. This will allow customers who have peak demands for natural gas during the injection season, to obtain the right to withdraw from storage on a firm basis. For Schedule G-SFS customers, the maximum daily counter-cyclical withdrawal rights that PG&E will offer is 135 MDth/d between April 1 and October 31.

Schedule G-SFS customers will also be offered counter-cyclical injection rights in November and March. These months allow Standard Firm Storage service customers to inject in November, to replenish inventory used in the summer or early fall, and to start injecting in March, prior to the traditional injection season, to replenish inventory that may be needed for summer peak use. For Schedule G-SFS customers, the maximum daily counter-cyclical injection rights that PG&E will offer is 76 MDth/d in November and March. No firm counter-cyclical injection is available through Schedule G-SFS in December through February.

4. Long-term Firm Storage Contracts

PG&E proposes that the maximum term for Schedule G-SFS or Schedule G-NFS (Negotiated Firm Storage) service be 15 years from the contract start date. PG&E proposes that customers who request long-term firm capacity must agree to pay the standard firm tariff rate, and therefore, will be subject to rate adjustments in future rate cases in which they can actively participate. PG&E states that long-term contracts will benefit customers, such as new power plant operators, who may be negotiating long-term, fixed-priced power sales and therefore need long-term gas transportation and supply contracts.

5. Negotiated Firm and As-Available Services

Except for the proposal that the maximum term for G-NFS service may be up to 15 years, as mentioned earlier, PG&E is not proposing any other changes to its current Schedules G-NFS or to G-NAS (Negotiated As-Available Storage) service.

PG&E offers negotiated firm storage service using the firm capacity that is assigned to the Standard Firm Storage service. Any injection or withdrawal capacity that is not used by firm storage customers is used to provide as-available storage services.

6. Hub Services

PG&E is not proposing any changes to its current parking and lending services, and such services should be retained without change.

7. Storage Shrinkage

PG&E proposes that all firm storage services, including Core Firm Storage, be subject to a storage shrinkage requirement upon injection. For Negotiated Firm Storage service, PG&E proposes that the storage shrinkage requirement be a negotiable element of the Negotiated Firm Storage service. The Operations and Balancing Services section describes PG&E's storage shrinkage proposal.

C. Position of the Parties

1. Duke

PG&E requests Commission authority to sell 4.5 MMDth of storage gas that had previously been classified as non-cycle working gas and to retain any gains or losses from the sale of that gas. PG&E's argument is that its shareholders should receive all of the proceeds from a sale of storage gas because shareholders received the short term interest rate on their investment.

Duke recommends that the Commission follow the precedent in D.02-11-028, and consider all the relevant factors before determining the allocation of the gain from PG&E's proposed sale of the non-cycle working gas. Duke asserts that the return that PG&E has received on the storage gas is just one element for the Commission to consider when it allocates any gain from the sale of the storage gas.

2. LGS

LGS points out that for core procurement groups to meet the Winter Firm Capacity Requirement, it will need an additional 75 MDth/d of withdrawal capacity. This additional capacity comes from a peaking arrangement between PG&E's Core Procurement Department, and PG&E's at-risk storage arm, California Gas Transmission. LGS is concerned about how this peaking arrangement was arrived at, and whether such an arrangement disadvantages third-party storage providers by shifting a portion of the at-risk storage to the core.

LGS also raised concerns about PG&E's request to reclassify and sell 4.5 MMDth of non-cycle working gas, with PG&E retaining all of the proceeds. LGS points out that since PG&E admits that this non-cycle working gas is necessary and useful in PG&E's utility operations, that PG&E should file § 851 application, or seek an exemption under § 853.

LGS is also concerned about the use of rental compression, which was installed for use as part of its at-risk storage operations. PG&E is now seeking to recover those rental compression costs through Standard Firm Storage services, balancing, and providing firm counter-cyclical injection rights to the core. LGS contends that the approval of PG&E's proposal will allow PG&E to shift almost 50% of the unrecovered costs of the rental compression to bundled customers. Since PG&E installed this rental compression at its own risk and without Commission approval, PG&E should be required to continue to bear those costs as part of its at-risk storage program. This gives California Gas Transmission an advantage over its storage competitors, who cannot shift costs in this fashion.

If the Commission is inclined to allow the use of the rental compression for the purposes proposed by PG&E, it should require PG&E to file an application for approval of the installation of the compression before any cost recovery from bundled ratepayers is allowed, and PG&E should be required to give notice of such an application to the parties to this proceeding.

3. NCGC

PG&E proposes to add firm counter-cyclical injection rights to the core's firm storage service. PG&E also proposes to assign 76 MDth/d to system balancing. NCGC believes that the allocation of injection capacity to system balancing service should be increased to 100 MMcf/d.

NCGC does not oppose the allocation of 50 MDth/d of counter-cyclical storage rights to the core, so long as the allocation does not jeopardize increasing injection rights to balancing service. To the extent there is insufficient storage injection capacity to increase the allocation of capacity to the core, while simultaneously increasing the allocation of installed injection capacity to system balancing, NCGC recommends that the allocation of injection capacity to the core for the winter months of December, January and February be reduced to the extent necessary to assure that there will be adequate injection capacity to provide the recommended level of system balancing.

4. ORA

ORA takes issue with PG&E's proposal to add firm counter-cyclical injection and withdrawal to Core Firm Storage services. ORA contends that it is not clear that core customers would benefit from such a proposal. Given the lack of need for this service, and the cost to the core of $550,000. ORA recommends that the proposal not be adopted.

5. PG&E

PG&E's storage assets provide firm and as-available storage service to core groups and to other market participants, and they also provide support for PG&E's system balancing service. PG&E proposes to reset the assignment of its firm storage capacity to balancing, Core Firm Storage, and Standard Firm Storage. PG&E's proposed modification to Core Firm Storage would increase core's firm withdrawal capacity by 75 MDth/d to meet the proposed Winter Firm Capacity Requirement. This would be accomplished by assigning existing capacity to Core Firm Storage through a peaking arrangement.

PG&E's proposed resetting of firm storage capacity would increase the amount of firm injection capacity to Core firm services, G-CFS. This would be accomplished by using the rental compression units that were acquired during the Gas Accord I period to support its sales under the at-risk storage program.

PG&E also proposes the following: (1) consolidate all core storage services under one tariff, Schedule G-CFS; (2) increase the cycled working gas inventory through the proposal sale of non-cycle working gas, and the reclassification of non-cycle working gas for balancing; (3) add firm counter-cyclical services to Schedule G-CFS and Schedule G-SFS; and (4) allow long-term storage contracts. PG&E contends that these proposals will provide its customers with more valuable services and an equitable cost allocation.

ORA asserts that PG&E has not made a sufficient showing that core customers would benefit from its firm counter-cyclical storage rights for core customers, and that the proposal should not be adopted at this time. PG&E's justification for assigning 50 MDth/d of counter-cyclical injection rights to the core is that PG&E believes the additional capacity will enable the core to better balance their supply and demand. PG&E's proposal on counter-cyclical rights should not be rejected simply because ORA chose not to participate in this issue. PG&E recommends that the Commission accept PG&E's proposed capacity allocation of firm counter-cyclical injection and withdrawal capacity to schedule G-CFS.

NCGC does not oppose the allocation unless the allocation jeopardizes increasing injection rights to balancing service. NCGC believes that PG&E should assign counter cyclical injection capacity to the core only to the extent to which there is sufficient existing injection capacity after increasing the allocation of injection to balancing service. NCGC also believes that the allocation of injection capacity to system balancing service should be increased to 100 Mcf/d. PG&E states that it has already proposed to increase injection assigned to balancing and believes the proposed assignment of 76 MDth/d balances the interests of all market participants.

PG&E proposes to provide additional withdrawal capacity to Core Firm Storage to meet the Winter Firm Capacity Requirement through the use of a peaking arrangement, which has been in place since the beginning of the Gas Accord. Because PG&E has been providing this service yearly since 1998, PG&E has stranded cost concerns if PG&E's proposal to provide the additional 75 MDth/d withdrawal capacity using PG&E storage is rejected.

LGS inferred that the peaking arrangement was the result of some back office, shady deal. PG&E asserts that LGS' inference is simply wrong. PG&E contends that the peaking arrangement between California Gas Transmission and PG&E's Core Procurement Department is proper. PG&E requests that the Commission approve PG&E's proposal to provide the additional 75 MMDth/d of withdrawal capacity to the core by incorporating the peaking agreement into Schedule G-CFS. PG&E recommends that the Commission approve its proposed withdrawal assignment, which includes the 75MDth/d to Schedule G-CFS.

PG&E proposes to increase the storage cycle inventory from 40.5 to 47 MMDth. To accomplish this, 6.5 MMDth of non-cycle working gas must be reclassified, and 2 MMDth would be retained and reclassified as working gas and assigned to balancing for the benefit of PG&E's transportation customers. The remaining 4.5 MMDth would be sold to create room for the customer-owned gas. PG&E requests permission to sell the 4.5 MMDth of gas. PG&E proposes that any loss or gain from the sale of the non-cycle working gas be assigned to PG&E because it owns the gas and has been fully at-risk for it.

PG&E opposes the proposals of Duke and LGS regarding the sale and treatment of the 4.5 MMDth of non-cycle working gas. PG&E asserts that the gas to be sold belongs to PG&E because it received only the short-term interest rate over the years. Also, the non-cycle working gas has not been depreciated, and depreciation expense has not been recovered in storage rates. Since PG&E's shareholders have been at-risk for the investment in this asset, PG&E believes that it should receive all of the proceeds from the sale of the non-cycle working gas. PG&E contends its situation is different from the sale of the cushion gas by SoCalGas in D.02-11-028.

With respect to the use of rental compression, PG&E contends that there is no cross subsidy. PG&E is resetting all firm capacity rights, including those for the at-risk G-SFS program. Also, incorporating the added injection and the associated costs in core's assignment lowers the per unit cost of injection while adding considerable flexibility. PG&E recommends the Commission approve its proposal to enhance its storage services using low cost rental compression to support this effort.

With respect to the long-term storage contracts, PG&E proposes that the maximum term for Schedule G-SFS and G-NFS service be 15 years from the contract start date. PG&E proposes to follow the guidance set in D.93-02-013 regarding contracts for existing and new facilities.

NCGC proposes to limit the amount of capacity available for long-term contracts, and a market concentration limit for PG&E storage. PG&E disagrees with the capacity limitation because its noncore storage program is smaller than LGS or Wild Goose. PG&E does not believe it should have to set aside a portion of its storage for short-term contracts when other storage alternatives are available. PG&E is also opposed to the market concentration limit unless such a limit applies to all three storage programs in Northern California and excludes firm storage capacity assigned to PG&E's Core Procurement Department.

D. Discussion

1. Assignments of Firm Storage Rights

PG&E proposes to make fixed assignments of firm storage rights to the Monthly Balancing Service, Core Firm Storage, and Standard Firm Storage. PG&E's proposed assignments of firm storage rights are shown in Table 6-2 of Exhibit 1. The assignments of firm storage rights also determines the allocation of the storage cost of service, as discussed in the Cost Allocation and Rate Design section. PG&E's proposed assignments are based on other proposals that PG&E seeks adoption of. To the extent other PG&E proposals are not adopted, this will affect the assignments of the firm storage rights.

Since we do not adopt the proposed Winter Firm Capacity Requirement, an adjustment to the assignments of capacity must be made. At page 4-8 of Exhibit 1, PG&E states that to meet the Winter Firm Capacity Requirement, "PG&E Core Procurement will need its current Gas Accord I assignment of PG&E's gas storage plus an additional assignment of 75 MDth/d of withdrawal capacity...." Since the Winter Firm Capacity Requirement is not needed, PG&E will just need the current assignment from the Gas Accord.31 As shown in Table 6-1 of Exhibit 1, and Table 14-7 of Exhibit 3, Core Firm Storage shall be assigned the following seasonal capacities for 2004: 156.6 MDth/d of injection; 33,477.7 MDth of inventory; and 1,111.2 MDth/d of withdrawal.

As discussed below, we deny PG&E's request to sell 4.5 MMDth of non-cycle working gas. As a result, the proposed inventory level for Standard Firm Storage will be reduced from 9.4 MMDth to 4.8 MMDth. This also affects the proposed injection and withdrawal because less inventory capacity is available. Therefore, as discussed below, we shall use the Gas Accord's current assignments for Standard Firm Storage as shown in Table 6-1 of Exhibit 1, and Table 14-7 of Exhibit 3, for 2004. Those assignments are: 22.4 MDth/d of injection; 4,782.5 MDth of inventory; and 158.7 MDth/d of withdrawal.

For balancing, as discussed in the Operations and Balancing Services section, we assign the following for 2004: 76 MDth/d of injection; 4.1 MMDth of inventory; and 76 MDth/d of withdrawal. The following Table 4 lists the assignment of firm storage rights for 2004.

Table 4

Services

Average Injection

MDth/d

Inventory

MDth

Average Withdrawal

MDth/d

Balancing Service

76

4,100.

76

Core Firm Storage

156.6

33,477.7

1111.2

Standard Firm Storage

22.4

4,782.5

158.7

Total

255

42,360.2

1345.9

2. Core Firm Storage Service

a. Basic Storage Services

PG&E proposes that Core Firm Storage be provided under a single tariff, Schedule G-CFS (Core Firm Storage), to PG&E's Core Procurement Department and to other core procurement groups. PG&E's Core Procurement Department would not have the option of rejecting its assignment of core firm storage capacity, which is the rule that is in effect today.

No one has objected to PG&E's proposal to provide Core Firm Storage to both its Core Procurement Department and to core procurement groups under a single tariff, Schedule G-CFS. We adopt PG&E's proposal to use a single tariff.

For core procurement groups that accept an assignment of storage inventory that is less than 1000 MDth, PG&E proposes to fix the firm injection and withdrawal rights for the season. PG&E currently does that for the small core procurement groups. PG&E's proposal notes, however, that:

"The fixed withdrawal rights are set in proportion to the minimum withdrawal capacity that PG&E Core Procurement must support, through the holding of inventory, to meet its Winter Firm Capacity Requirement. A comparable fixed injection right is also set for these smaller CPGs. All CPGs that accept a share of Core Firm Storage capacity will be required to maintain their storage inventory at sufficient levels to support withdrawal rates consistent with the Winter Firm Capacity Requirement." (Ex. 1, p. 6-10.)

Since we do not adopt the proposal for a Winter Firm Capacity Requirement for CPGs, the existing guideline in the Gas Accord to meet the core's winter needs shall be used to set the firm injection and withdrawal rights for the season for CPGs that accept an assignment of storage inventory that is less than 1000 MDth. The existing guideline to meet the core's winter needs is close to a 1-in-3 year cold temperature event.

For CPGs that have inventory rights greater than 1,000 MDth, PG&E proposes to vary the injection and withdrawal rights according to its injection and withdrawal rights curve shown in Table 6-3 of Exhibit 1.

For 2003, the ratio of injection to inventory to withdrawal for Core Firm Service is about 1:1:5. For 2004, PG&E proposes that Schedule G-CFS injection and withdrawal rights vary based upon the volume of gas that is in inventory. For 2004, the overall average yearly ratio of injection to inventory to withdrawal is 1.2:1:5.4. (Ex. 1, p. 6-10; Ex. 15, p. 13.)

According to PG&E, the injection and withdrawal rights curve reflects the seasonal use of these assets by core procurement groups. By reducing the firm rights to reflect their seasonal use, PG&E states that the "core storage rate will reflect this seasonal profile," and "the core storage rate will be less than it otherwise would be if a higher level of firm rights are assigned." (Ex. 1, p. 6-11.) PG&E states, however, that the withdrawal rights profile "will be set equal to or above the levels necessary to meet the Winter Firm Capacity Requirement...." (Ex. 1, p. 6-11.) Since the withdrawal rights are tied to the Winter Firm Capacity Requirement, the injection and withdrawal rights curve in Table 6-3 of Exhibit 1, and the overall average ratio of injection to inventory to withdrawal, will likely be affected by our non-adoption of the Winter Firm Capacity Requirement. (See Ex. 15, p. 11.)

PG&E's seasonal adjustment in the injection and withdrawal rights curve appears to be of benefit in possibly lowering the core storage rate. However, we do not have sufficient information to allow us to develop a new injection and withdrawal rights curve, which reflects seasonal use only.

Since the injection to inventory to withdrawal ratio affects the cost allocation for storage rates, we shall adopt the Gas Accord's assignment of injection, inventory, and withdrawal, as shown in Appendix A at page 27, and which is reflected in Table 4 above. PG&E shall use the Gas Accord's assignments for Core Firm Storage in 2004, and shall use the Gas Accord's ratio of injection to inventory to withdrawal for Core Firm Service in 2004.

(2) Firm Counter-Cyclical Storage Rights
for Core Firm Storage

PG&E proposes to add firm counter-cyclical injection and withdrawal to the Core Firm Storage service. This service would provide 50 MDth/d of counter-cyclical rights for each day of the year. The incremental cost to the core for counter-cyclical service would be $414,000.

ORA objects to PG&E's proposal to add firm counter-cyclical storage because no need has been shown for such a service. NCGC does not oppose the counter-cyclical storage rights to the core so long as the allocation does not jeopardize increasing the injection rights for balancing service.

We have considered the cost of such a service, and the flexibility that such a service offers. Given the relatively low cost of such service, and its ability to provide CPGs with additional flexibility to meet their gas needs during the non-injection season, we adopt PG&E's proposal for counter-cyclical service to Core Firm Storage.

3. Standard Firm Storage Service

a. Basic Storage Services, Non-Cycle
Working Gas, and Compression

PG&E proposes the adoption of a new tariff, Schedule G-SFS, to replace the existing Schedule G-FS (Firm Storage) tariff. The new tariff schedule would offer more inventory, counter-cyclical injection and withdrawal rights, and the opportunity to secure a long-term contract.

The new tariff would include the offering of additional services or terms that PG&E is proposing. We adopt PG&E's proposal to have Schedule G-SFS replace its existing Schedule G-FS tariff. However, the new Schedule G-SFS tariff shall conform to the proposals that we adopt, and which are discussed below.

With respect to offering more inventory, PG&E plans to accomplish this through lowering the withdrawal to inventory ratio because Schedule G-SFS customers do not require the same high rate of withdrawal needed for residential and commercial temperature-sensitive demand. By lowering the withdrawal ratio, all of the firm withdrawal rights can still be met by using lower pressure and a correspondingly lower inventory. The lower inventory would allow PG&E to have less non-cycle working gas in the storage field. The lower amount of non-cycle working gas in the field creates more space for gas that can be cycled. Thus, more storage inventory can be offered to customers. PG&E states that by reducing the withdrawal to inventory ratio for Schedule G-SFS, the inventory available to cycle can be increased from 40.5 MMDth to 47 MMDth.

PG&E proposes to reclassify 6.5 MMDth of non-cycle working gas that would no longer be needed to meet the firm withdrawal rights. Of the 6.5 MMDth of gas, PG&E proposes to retain 2 MMDth and reclassify it as working gas to be used for the benefit of balancing PG&E's transportation customers.

For the remaining 4.5 MMDth of non-cycle working gas, PG&E requests permission to sell this gas on a one-time basis. PG&E contends that since it owns the gas, any gain or loss from the sale of this non-cycle working gas should be assigned to PG&E.

Duke and LGS object to PG&E's proposed sale of the 4.5 MMDth of non-cycle working gas.

There are several reasons why we deny PG&E's request to sell the 4.5 MMDth of non-cycle working gas. First, this proceeding is not the appropriate forum in which to seek permission to sell the gas. This proceeding addresses PG&E's gas structure for its transmission and storage systems, and rates, for 2004. To add a request to sell 4.5 MMDth of gas, in a one-paragraph reference in a multi-page document, is not appropriate given all of the other issues that confront us in this proceeding. (See Ex. 1, pp. 6-13 to 6-14.)

Our second reason for denying PG&E's request to sell the 4.5 MMDth of non-cycle working gas is PG&E's testimony lacks the necessary details for us to properly evaluate whether such a sale should be permitted. PG&E has not explained the origins of this non-cycle working gas, how much it paid for the gas, when it was acquired, the rate treatment that it has received for the gas, whether PG&E's storage operations justify such a sale, the projected amount PG&E is likely to receive for the gas, and how the gain or loss should be accounted for.

Our third reason is § 851 provides that no public utility shall sell "property necessary or useful in the performance of its duties to the public" without first seeking Commission authorization to do so. We agree with LGS' reasoning that PG&E should be required to file a § 851 application for the proposed sale of this gas. PG&E's briefs do not address the § 851 argument. PG&E acknowledges in its brief that the non-cycle working gas is providing the pressure to meet the storage withdrawal needs of its customers. (See PG&E Opening Brief, p. 38.) Thus, this proposed gas sale falls squarely within § 851. The concerns that we described in our second reason, should be addressed in a § 851 application so that the Commission has the information it needs to make an informed decision.

Accordingly, PG&E's request to sell the 4.5 MMDth of non-cycle working gas is denied without prejudice.

The issue regarding PG&E's proposed reclassification of 2 MMDth for balancing purposes, is discussed in the Operations and Balancing Services section of this decision.

PG&E's proposed assignment of firm storage rights, shown in Table 6-2 of Exhibit 1, requires more compression than is currently assigned. For 2004, PG&E proposes to use rental compressor units to provide additional firm injection for Schedule G-SFS, for balancing, and for providing counter-cyclical injection rights to the core.

LGS is opposed to the use of the rental compression, and points out that PG&E is at risk for the compressor units. To allow PG&E to reclassify the compressors so that the costs of such units are paid by captive core customers and/or captive transmission customers would be anticompetitive.

PG&E points out that it is at risk for selling enough services to recover the cost of its noncore storage services.

We will permit PG&E to use the rental compression equipment to provide the injection for Schedule G-SFS, for balancing, and for providing counter-cyclical injection rights to the core. The arguments of LGS and ORA are offset by the benefits the additional services provide to Core Firm Storage and to Standard Firm Storage customers, and for balancing.

Table 6-4 of Exhibit 1 shows the average seasonal injection and withdrawal rights that PG&E proposes to assign to Standard Firm Service. Table 6-4 shows that Standard Firm Service would be assigned 9.4 MMDth of inventory.

Since we deny PG&E's request to sell 4.5 MMDth of non-cycle working gas, the inventory assigned to Standard Firm Storage will be reduced to 4.8 MMDth. This affects the injection to inventory to withdrawal ratio of 2.2:1:3.1. (See Ex. 15, p. 14.) The reduction in the inventory from 9.4 MMDth to 4.8 MMDth also affects PG&E's plans to lower the withdrawal ratio for Schedule G-SFS customers.

The injection to inventory to withdrawal ratio affects the cost allocation of storage rates. Due to the non-adoption of the sale of the non-cycle working gas, the 2004 inventory will remain at 4.8 MMDth. Since the inventory remains unchanged from the Gas Accord, we adopt the Gas Accord's assignment of injection, inventory and withdrawal for Standard Firm Service as shown in Table 6-1 of Exhibit 1, and which is reflected in Table 4 above. PG&E shall use the Gas Accord's assignments for Standard Firm Storage in 2004, and shall use the Gas Accord's ratio of injection to inventory to withdrawal for Standard Firm Storage in 2004.

PG&E proposes to offer counter-cyclical storage rights to Schedule G-SFS customers. Under this service, PG&E would allow Schedule G-SFS customers to choose any three months of firm counter-cyclical withdrawal rights during the injection season of April 1 through October 31. This will allow those customers who have peak demands during those months to withdraw gas from storage on a firm basis. Schedule G-SFS customers will also be offered counter-cyclical injection rights in November and March. The counter-cyclical injection is to allow those customers with peak demands in the summer and early fall to replenish their supplies.

On an annual basis, the average daily capacity allocated to Schedule G-SFS customers for counter-cyclical services is 47 MDth/d.

Except for LGS' concern about the use of rental compression, no one has objected to PG&E's proposed counter-cyclical storage rights for Standard Firm Storage Service. We adopt PG&E's proposal to offer this service for Schedule G-SFS customers. Based on PG&E's experience, there are some gas customers, such as food processors and electric generators, who need peak supplies during the injection season. The counter-cyclical service will provide Schedule G-SFS customers with additional flexibility to meet their gas needs, while allowing PG&E to market available counter-cyclical capacity.

4. Long-Term Firm Storage Contracts

PG&E proposes that the maximum term for Schedule G-SFS or Schedule G-NFS service be for 15 years from the contract start date. Under the existing procedures, individual agreements for longer terms can be negotiated, but must be filed with the Commission for approval. As part of PG&E's proposal, it would file any executed agreement that is longer than five years with the Commission for informational purposes.

Although Duke and NCGC expressed some initial reservations about the long-term firm storage contracts in their testimony, they did not comment about PG&E's proposal in their briefs. PG&E's rebuttal testimony and its opening brief, appear to have responded to their concerns.

In D.93-02-013, we approved long-term storage contracts for SoCalGas. (48 CPUC2d 107, 128-130.) PG&E contends that the long-term contracts will be of benefit to those customers, such as electric generators, who need long-term gas transportation and supply contracts. Given our previous approval of long-term storage contracts for SoCalGas, and the benefit that a long-term storage contract may bring to a customer, we will adopt PG&E's proposal to offer long-term contracts of up to 15 years for Schedule G-SFS and Schedule G-NFS customers.

5. Storage Shrinkage

PG&E proposes that all firm storage services, including Core Firm Storage, be subject to a storage shrinkage requirement upon injection. PG&E's proposal for storage shrinkage is discussed in the Operations and Balancing Services section.

21 PG&E's storage assets are operated by PG&E's California Gas Transmission (CGT) unit.22 Market storage services does not include firm storage that is assigned to core customers. Market storage services cover Standard Firm Storage, negotiated firm storage, negotiated as-available storage, and parking and lending services. Core Firm Storage customers may also use market storage services to supplement their core service or to purchase additional storage capacity.23 Table 1 comes from Table 6-2 of Exhibit 1.24 The storage injection capacities shown in the table include rented compressor units installed during the Gas Accord period. 25 The amounts shown for inventory are the maximum inventory assigned.26 The amounts shown for balancing are for year-round injection and withdrawal capacity.27 The withdrawal right for G-CFS reflects the required withdrawal to meet the proposed core Winter Firm Capacity Requirement. 28 The withdrawal right shown for G-SFS is the average assigned withdrawal for December through February.29 Should a flood occur causing the rental compression at McDonald Island to become inoperable, PG&E proposes to provide service to Core Firm Storage customers and monthly balancing first, and then to Schedule G-SFS customers, and lastly to remaining market storage services customers. In other circumstances where firm injection capacity is constrained, PG&E proposes to prorate all firm injection rights equally.30 For the period April - October, each G-SFS customer will be allowed to select its own three months for counter-cyclical service from the seven-month season. The customer may choose any three months, consecutive or non-consecutive.31 Since we are not adopting PG&E's proposed assignment of an additional 75 MDth/d of withdrawal capacity to Core Firm Storage, there is no need to address the peaking arrangement arguments. The issue about whether third-party storage providers can provide this service has also been addressed.